Separation systems for removing water and light end hydrocarbons from oil in a multiphase hydrocarbon flowstream are well known in the art. In certain oilfields, the multiphase hydrocarbon flowstream contains primarily oil with lesser quantities of water, gas and possibly sediment (i.e., solids) fractions. In addition, the oil may contain a number of light end hydrocarbons, which can be defined as the more volatile components of the crude oil, such as methane, butane, ethane and propane. At some point prior to the oil refining process, the water, gas and sediment must be removed from the oil in order to meet custody transfer specifications for basic sediment and water (BS&W) content and volatility (e.g. Reed Vapor Pressure).
Separation systems which use heat to facilitate the separation of water and light end hydrocarbons from oil are commonly referred to as heater-treaters. An example of a prior art heater-treater separation system is shown in FIG. 1. This separation system, generally 10, includes a horizontal separator vessel 12 having an upstream end 14, a downstream end 16, a multiphase fluid inlet 18, a gas outlet 20, a water outlet 22 and an oil outlet 24. The internal volume of the separator 5 vessel 12 is generally divided into a heating section 26, a separation section 28 and an oil accumulation section 30. The heating section 26 is separated from the separation section 28 by a divider plate 32, and the separation section 28 is separated from the oil accumulation section 30 by an overflow weir 34.
In this example, the separation system 10 employs a fire tube heater to heat the hydrocarbon fluid as it flows through the heating section 26. The fire tube heater comprises a U-shaped fire tube 36 (also referred to as a heat tube or a burner tube) which is heated by a gas burner 38. In operation, the burner 38 ignites a flame which produces hot combustion gases that flow through and heat the metal wall of the fire tube, which in turn heats the hydrocarbon fluid.
However, fire tube heaters have several major drawbacks. For example, fire tube heaters are not easily scalable for large flowrates due to the low heat transfer surface area to volume ratio. Thus, for large flowrates several parallel fire tubes are normally required. Also, the trend in field development for the shale market is shifting towards the use of Central Production Facilities, where oil from several well-pad locations is processed. This requires the use of many fire tubes at a single facility, which is not cost effective.
In addition, fire tube heaters require that the fire tube be positioned within the separator vessel. As a result, the flame contained in the fire tube is present inside the vessel where the hydrocarbon flowstream is processed, which creates a safety concern. Furthermore, because the hydrocarbon fluid is heated by a metal tube containing a flame, the temperature of the metal tube cannot be accurately controlled. What is more, the temperature is usually high enough to cause the oil to boil, which can result in pitting of the tube material. Consequently, fire tubes need regular maintenance and inspections, and failures of fire tubes due to this problem have been known to occur. Also, the high temperature of the fire tube can cause fouling of the surface of the tubes by coke and scale deposits, which can inhibit heat transfer and reduce the thermal efficiency of the fire tube heater over time. Furthermore, fire tubes are connected to the separator vessel by a relatively large and complicated flange, which is costly to produce and install.